CN111133169B - Internal and external downhole architecture with downlink activation - Google Patents

Abstract

The present invention provides systems and methods for performing a downhole operation in a borehole, the method comprising: moving an inner structure and an outer structure within the borehole using surface equipment, the outer structure being equipped with an interaction device and the inner structure being configured to move relative to the outer structure in a direction parallel to the borehole by the surface equipment; transmitting, by a transmitter, a downlink instruction to an internal structure; and executing an interaction routine with the interaction device in response to the downlink instructions, wherein the interaction routine comprises an interaction located at least partially outside of the external structure to perform the downhole operation.

Description

Internal and external downhole architecture with downlink activation

Cross Reference to Related Applications

This application claims the benefit of U.S. patent application 15/715298 filed on 26.9.2017, which is incorporated herein by reference in its entirety.

Technical Field

The present invention relates generally to downhole operations and downlink activation of components used in downhole operations.

Background

Boreholes are drilled deep underground for many applications such as carbon dioxide sequestration, geothermal production, and oil and gas exploration and production. In all of these applications, boreholes are drilled so that they pass through or allow access to materials (e.g., gases or fluids) contained in the formations below the surface. Different types of tools and instruments may be disposed in the borehole to perform various tasks and measurements.

Generally, completion equipment, such as a liner hanger, is hydraulically activated within the borehole. The work string (which contains the liner running tool) includes a plugging device for isolating the activation port of the liner hanger from the ball seat. The ball falls downhole and the pump pressure is transferred to the activation piston of the liner hanger. Thus, activating the piston engages the liner hanger with the liner. The disclosure herein provides improvements to activating downhole components, such as activation of a liner hanger.

Disclosure of Invention

Disclosed herein are systems and methods for performing a downhole operation in a borehole, the methods comprising: moving an inner structure and an outer structure within the borehole using surface equipment, the outer structure being equipped with an interaction device and the inner structure being configured to move relative to the outer structure in a direction parallel to the borehole by the surface equipment; transmitting, by a transmitter, a downlink instruction to an internal structure; and executing an interaction routine with the interaction device in response to the downlink instructions, wherein the interaction routine comprises an interaction located at least partially outside of the external structure to perform the downhole operation.

Drawings

The subject matter which is regarded as the invention is particularly pointed out and distinctly claimed in the claims at the conclusion of the specification. The foregoing and other features and advantages of the invention will be apparent from the following detailed description taken in conjunction with the accompanying drawings, in which like elements have like numerals, and in which:

FIG. 1 is an example of a system for performing a downhole operation that may employ embodiments of the present disclosure;

FIG. 2 is a diagram of an exemplary drill string that may employ embodiments of the present disclosure, the exemplary drill string including an inner tubular string and an outer tubular string, wherein the inner tubular string is connected to a first location of the outer tubular string to drill a first size hole;

FIG. 3 is a schematic view of a downhole system having an internal structure that is movable relative to an external structure that may employ embodiments of the present disclosure;

fig. 4A is a schematic illustration of a downhole system according to an embodiment of the present disclosure;

FIG. 4B is a schematic diagram of the system of FIG. 4A, illustrating a first step in the operation of the system;

FIG. 4C is a schematic diagram of the system of FIG. 4A, illustrating a second step in the operation of the system;

FIG. 4D is a schematic diagram of the system of FIG. 4A, illustrating a third step in the operation of the system;

fig. 5A is a schematic diagram of an internal structure of a system according to an embodiment of the present disclosure;

fig. 5B is a schematic illustration of the internal structure shown in fig. 5A housed within an external structure, according to an embodiment of the present disclosure;

fig. 6A is a schematic illustration of an activation section of an internal structure in a disengaged state according to an embodiment of the present disclosure;

FIG. 6B is a schematic view of the activation segment of FIG. 6A in an engaged state and illustrating a transition from a disengaged state to an engaged state;

FIG. 6C is a schematic view of the activation segment of FIG. 6A in an engaged state and illustrating a transition from the engaged state to the disengaged state;

fig. 7A is a first view of a valve section of an internal structure according to an embodiment of the present disclosure;

FIG. 7B is a second view of the valve segment of FIG. 7A; and

fig. 8 is a flow chart for performing a downhole operation according to an embodiment of the present disclosure.

Detailed Description

FIG. 1 shows a schematic diagram of a system for performing a downhole operation. As shown, the system is a drilling system 10 that includes a drill string 20 having a drilling assembly 90 (also referred to as a Bottom Hole Assembly (BHA)) conveyed in a borehole 26 penetrating a formation 60. The drilling system 10 includes a conventional derrick 11 erected on a floor 12 supporting a rotary table 14 that is rotated at a desired rotational speed by a prime mover, such as an electric motor (not shown). The drill string 20 includes a drilling tubular 22, such as a drill pipe, that extends downwardly from the rotary table 14 into a borehole 26. A fracturing tool 50 (such as a drill bit attached to the end of the BHA 90) fractures the formation while rotating to drill the borehole 26. The drill string 20 is coupled to surface equipment, such as a system for lifting, rotating, and/or propelling (including but not limited to) a drawworks 30 via a kelly joint 21, swivel 28, and line 29 through a sheave 23. In some embodiments, the surface equipment may include a top drive (not shown). During drilling operations, the drawworks 30 is operated to control the weight-on-bit, which affects the rate of penetration. The operation of the drawworks 30 is well known in the art and therefore will not be described in detail herein.

During drilling operations, a suitable drilling fluid 32 (also referred to as "mud") from a source or mud pit 31 is circulated under pressure through the drill string 20 by a mud pump 34. The drilling fluid 31 enters the drill string 20 via the surge arrestor 36, the fluid line 38, and the kelly joint 21. The drilling fluid 31 is discharged at the borehole bottom 51 through an opening in the fracturing tool 50. Drilling fluid 31 is circulated uphole through the annular space 27 between the drill string 20 and the borehole 26 and returned to the mud pit 32 via a return line 35. Sensor S1 in line 38 provides information about the fluid flow rate. A surface torque sensor S2 and a sensor S3 associated with the drill string 20 provide information about the torque and rotational speed of the drill string, respectively. Additionally, one or more sensors (not shown) associated with the pipeline 29 are used to provide hook loading of the drill string 20 and other desired parameters related to the drilling of the wellbore 26. The system may also include one or more downhole sensors 70 positioned on the drill string 20 and/or BHA 90.

In some applications, the fracturing tool 50 is rotated by merely rotating the drill pipe 22. However, in other applications, the drilling motor 55 (mud motor) disposed in the drilling assembly 90 is used to rotate the fracturing tool 50 and/or to superimpose or supplement the rotation of the drill string 20. In either case, the rate of penetration (ROP) of the fracturing tool 50 into the borehole 26 for a given formation and drilling assembly is largely dependent on the weight-on-bit and the rotational speed of the drill bit. In one aspect of the embodiment of fig. 1, the mud motor 55 is coupled to the fracturing tool 50 via a drive shaft (not shown) disposed in a bearing assembly 57. As the drilling fluid 31 passes under pressure through the mud motor 55, the mud motor 55 rotates the fracturing tool 50. The bearing assembly 57 supports the radial and axial forces of the fracturing tool 50, the lower thrust of the drilling motor, and the reactive upward load from the applied weight-on-bit. Stabilizers 58 coupled to the bearing assemblies 57 and other suitable locations act as centralizers for the lowermost portion of the mud motor assembly and other such suitable locations.

The surface control unit 40 receives signals from downhole sensors 70 and equipment via transducers 43 placed in the fluid line 38, such as pressure transducers, as well as signals from sensors S1, S2, S3, hook load sensors, RPM sensors, torque sensors and any other sensors used in the system, and processes such signals according to programmed instructions provided to the surface control unit 40. The surface control unit 40 displays desired drilling parameters and other information on a display/monitor 42 that are used by an operator at the drilling rig site to control the drilling operation. The ground control unit 40 includes a computer; a memory for storing data, computer programs, models and algorithms accessible to a processor in a computer; a recorder such as a tape unit, a memory unit, or the like, for recording data; and other peripheral devices. The surface control unit 40 may also include a simulation model used by the computer to process data according to programmed instructions. The control unit is responsive to user commands entered through a suitable device, such as a keyboard. The control unit 40 is adapted to activate an alarm 44 in the event of certain unsafe or undesirable operating conditions.

The drilling assembly 90 also contains other sensors and devices or tools for providing various measurements related to the formation surrounding the borehole and for drilling the wellbore 26 along a desired path. Such an apparatus may include a device for measuring the resistivity of the formation near and/or ahead of the drill bit, a gamma ray device for measuring the gamma ray intensity of the formation, and a device for determining the inclination, azimuth, and position of the drill string. Formation resistivity tools 64 made according to embodiments described herein may be coupled at any suitable location, including above the lower promoter assembly 62, for estimating or determining formation resistivity near or ahead of the fracturing tool 50 or at other suitable locations. Inclinometer 74 and gamma ray equipment 76 may be suitably positioned for determining the inclination of the BHA and the formation gamma ray intensity, respectively. Any suitable inclinometer and gamma ray equipment may be used. Additionally, an azimuth device (not shown), such as a magnetometer or gyroscope device, may be utilized to determine the drill string azimuth. Such devices are known in the art and are therefore not described in detail herein. In the exemplary configuration described above, the mud motor 55 transmits power via the hollow axial fracturing tool 50, which also enables drilling fluid to be transmitted from the mud motor 55 to the fracturing tool 50. In alternative embodiments of the drill string 20, the mud motor 55 may be coupled below the formation resistivity tool 64 or in any other suitable location.

Still referring to fig. 1, other Logging While Drilling (LWD) equipment (generally represented herein by the numeral 77), such as equipment for measuring formation porosity, permeability, density, rock properties, fluid properties, and the like, may be placed at suitable locations in the drilling assembly 90 for providing information useful for evaluating subsurface formations along the borehole 26. Such equipment may include, but is not limited to, temperature measurement tools, pressure measurement tools, borehole diameter measurement tools (e.g., calipers), acoustic tools, nuclear magnetic resonance tools, and formation testing and sampling tools.

The above-described equipment transmits data to a downhole telemetry system 72, which in turn transmits the received data uphole to the surface control unit 40. The downhole telemetry system 72 also receives signals and data from the surface control unit 40 (which includes a transmitter) and transmits such received signals and data to appropriate downhole equipment. In one aspect, a mud pulse telemetry system may be used to communicate data between the downhole sensors 70 and equipment and surface equipment during drilling operations. A transducer 43 placed in the mud supply line 38 detects mud pulses in response to data transmitted by the downhole telemetry system 72. The transducer 43 generates electrical signals in response to mud pressure changes and transmits such signals to the surface control unit 40 via conductor 45. In other aspects, any other suitable telemetry system may be used for two-way data communication (e.g., downlink and uplink) between the surface and the BHA 90, including, but not limited to, acoustic telemetry systems, electromagnetic telemetry systems, optical telemetry systems, wired pipe telemetry systems, which may utilize wireless couplers or repeaters in the drill string or wellbore. Wired pipes may be constructed by connecting drill pipe sections, where each pipe section includes a data communication link extending along the pipe. The data connection between the pipe sections may be made by any suitable method including, but not limited to, hard or optical connections, inductive connections, capacitive connections, resonant coupling connections, or directional coupling connection methods. In the case of coiled tubing as the drill pipe 22, the data communication link may be along the side of the coiled tubing run.

The drilling systems described thus far relate to those that utilize drill pipe to convey the drilling assembly 90 into the borehole 26, wherein the weight on bit is typically controlled from the surface by controlling the operation of the drawworks. However, a number of current drilling systems, particularly those used for drilling highly deviated and horizontal wellbores, utilize coiled tubing to convey the drilling assembly downhole. In such applications, sometimes a thruster is deployed in the drill string to provide the desired force on the drill bit. Additionally, when coiled tubing is utilized, rather than rotating the tubing via a rotary table, the tubing is injected into the wellbore via a suitable injector while a downhole motor, such as a mud motor 55, rotates the fracturing tool 50. For offshore drilling, offshore drilling rigs or vessels are used to support drilling equipment, including drill strings.

Still referring to FIG. 1, a formation resistivity tool 64 may be provided that includes, for example, a plurality of antennas including, for example, transmitters 66a or 66b and/or receivers 68a or 68b. Resistivity may be a formation property of interest in making drilling decisions. Those skilled in the art will appreciate that other formation property tools may be used in addition to or in place of the formation resistivity tool 64.

Liner drilling may be one configuration or operation for providing fracturing equipment and is therefore becoming increasingly attractive in the oil and gas industry because of several advantages over conventional drilling. One example of such a configuration is shown and described in commonly owned U.S. patent 9,004,195 entitled "Apparatus and Method for Drilling a Wellbore, setting a Liner, and Cementing the Wellbore During a Single Trip," which is hereby incorporated by reference in its entirety. Importantly, although the rate of penetration is relatively low, the time to align the liner to the target is reduced because the liner is run in while drilling the wellbore. This may be beneficial in expanded formations where the shrinkage of the borehole may hinder the installation of a liner. Furthermore, drilling in depleted and unstable formations using a liner minimizes the risk of pipe or drill string sticking due to borehole collapse.

While fig. 1 is shown and described with respect to a drilling operation, those skilled in the art will appreciate that similar configurations may be used to perform different downhole operations, albeit with different components. For example, wireline, coiled tubing, and/or other configurations may be used, as is known in the art. Additionally, production configurations may be employed for extracting material from and/or injecting material into the formation. Thus, the present disclosure is not limited to drilling operations, but may be used for any suitable or desired downhole operation or operations.

Turning now to fig. 2, a schematic line drawing of an exemplary system 200 is shown that includes an inner structure 210 disposed within an outer structure 250. In this embodiment, the inner structure 210 is an inner tubular string that includes a bottom hole assembly, as described below. Further, as shown, the outer structure 250 is a casing or outer tubular string. The inner structure 210 includes various tools within and movable relative to the outer structure 250. According to embodiments of the present disclosure, the inner structure 210 and the outer structure 250 may be moved together or independently of each other by ground equipment. As described herein, various tools of the inner structure 210 may act on and/or with portions of the outer structure 250 to perform certain downhole operations. Further, various tools of the inner structure 210 may extend beyond the outer structure 250 to perform other downhole operations, such as drilling.

In this embodiment, the inner structure 210 is adapted to pass through the outer structure 250 and connect to the inner side 250a of the outer structure 250 at a plurality of spaced apart locations (also referred to herein as "landings" or "landing locations"). The illustrated embodiment of the outer structure 250 includes three landing portions, a lower landing portion 252, a middle landing portion 254, and an upper landing portion 256. The internal structure 210 includes a drilling or fracturing assembly 220 (also referred to as a "bottomhole assembly") connected to the bottom end of a tubular member 201, such as a string of jointed tubing or coiled tubing. The drilling assembly 220 includes, at its bottom end, a first fracturing device 202 (also referred to herein as a "pilot bit") for drilling a first size bore 292a (also referred to herein as a "pilot hole"). The drilling assembly 220 also includes a steering apparatus 204, which in some embodiments may include a plurality of force applying members 205 configured to extend from the drilling assembly 220 to apply a force on the wall 292a' of the pilot hole 292a drilled by the pilot bit 202 to steer the pilot bit 202 in a selected direction to drill a deviated pilot hole. The drilling assembly 220 may also include a drilling motor 208 (also referred to as a "mud motor") configured to rotate the pilot bit 202 when the fluid 207 is supplied under pressure to the inner structure 210.

In the configuration of fig. 2, the drilling assembly 220 is also shown as including an underreamer 212 that can be extended and retracted as needed from and toward the body of the drilling assembly 220 to enlarge the guide bore 292a to form the wellbore 292b to at least the size of the outer string. In various embodiments, such as shown, the drilling assembly 220 includes a plurality of sensors (collectively referred to as numerals 209) for providing signals related to a plurality of downhole parameters, including, but not limited to, various properties or characteristics of the formation 295 and parameters related to the operation of the system 200. The drilling assembly 220 also includes control circuitry (also referred to as a "controller") 224, which may include: a circuit 225 for conditioning signals from the various sensors 209; a processor 226, such as a microprocessor; data storage devices 227, such as solid state memory; and programs 228 accessible to processor 226 for executing instructions contained in programs 228. The controller 224 communicates with a surface controller (not shown) via suitable telemetry devices 229a that provide two-way communication between the internal structure 210 and the surface controller. The telemetry unit 229a may utilize any suitable data communication technique, including but not limited to mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, and wired pipe. The power generation unit 229b in the internal structure 210 provides power to various components in the internal structure 210, including the sensors 209 and other components in the drilling assembly 220. The drilling assembly 220 may also include a second power generation device 223 that is capable of providing power regardless of the presence of power generated using the drilling fluid 207 (e.g., a third power generation device 240b described below).

In various embodiments, such as the one shown, the inner structure 210 can further include a sealing device 230 (also referred to as a "sealing nipple") that can include a sealing element 232 (such as a retractable packer) configured to provide a flow barrier or fluid seal between the inner structure 210 and the outer structure 250 when the sealing element 232 is activated in the deployed state. Additionally, the internal structure 210 may include a tailpipe drive sub 236 that includes attachment devices 236a,236b (e.g., latch elements, anchors, slips, etc.) that may be removably connected to any of the landing positions in the external structure 250. Attachment devices 236a,236b are also referred to herein as "external engagement elements". Inner structure 210 may also include a hanger activation device or sub 238 comprising an activation tool having seal members 238a,238b configured to activate rotatable hanger 270 in outer structure 250. The internal structure 210 may include: a third power generation device 240b, such as a turbine-driven device, operated by the fluid 207 flowing through the inner string 210, configured to generate electricity; and a second bidirectional telemetry device 240a comprising a transmitter utilizing any suitable communication technique including, but not limited to, mud pulse telemetry, acoustic telemetry, electromagnetic telemetry, and wired pipe telemetry. The internal structure 210 may also include a fourth power generation device 241 regardless of whether there is a power generation source, such as a battery, that uses the drilling fluid 207. The inner structure 210 may also include a short drill pipe 244 and a burst sub 246.

Still referring to fig. 2, the outer structure 250 includes a tailpipe 280 that may house or contain a second fracturing apparatus 251 (e.g., also referred to herein as a reamer bit) at its lower end. Reamer bit 251 is configured to enlarge the remainder of bore 292a formed by pilot bit 202. In various aspects, attaching the inner tubular string at the lower landing 252 enables the inner structure 210 to drill a pilot hole 292a, and the under reamer 212 to enlarge the pilot hole to a drill hole 292 that is at least as large in size as the outer structure 250. Attaching the inner structure 210 at the intermediate land portion 254 enables the reamer bit 251 to enlarge a section of the bore 292a that is not enlarged by the under-reamer 212 (also referred to herein as a "residual bore" or "residual pilot bore"). Attaching the inner structure 210 at the upper landing 256 enables cementing of the annulus 287 between the liner 280 and the formation 295 without pulling the inner structure 210 to the surface, i.e., in a single pass of the system 200 downhole. The lower land portion 252 includes internal splines 252a and collet grooves 252b for attachment to attachment devices 236a and 236b of the tailpipe drive sub 236. Similarly, the intermediate land portion 254 includes internal splines 254a and collet grooves 254b, and the upper land portion 256 includes internal splines 256a and collet grooves 256b. For purposes of this disclosure, any other suitable attachment mechanism and/or latching mechanism for connecting the inner structure 210 to the outer structure 250 may be utilized.

The outer structure 250 may also include a flow control device 262, such as a backflow prevention assembly or device, disposed in the interior 250a of the outer structure 250 adjacent the lower end 253 thereof. In fig. 2, flow control device 262 is in a deactivated or open position. In this position, the flow control device 262 allows fluid communication between the well bore 292 and the interior 250a of the outer structure 250. In some embodiments, the flow control device 262 may be activated (i.e., closed) when the pilot bit 202 is retracted inside the outer structure 250 to prevent fluid communication from the wellbore 292 to the interior 250a of the outer structure 250. When pilot bit 202 extends beyond outer structure 250, flow control device 262 is deactivated (i.e., opened). In one aspect, the force applying member 205 or another suitable device may be configured to activate the flow control device 262.

A reverse flow control device 266, such as a reverse baffle or other backflow prevention structure, may also be provided to prevent fluid communication from the interior of the outer structure 250 to a location below the reverse flow control device 266. Outer structure 250 also includes a hanger 270 that is activatable by hanger activation sub 238 to anchor outer structure 250 to main casing 290. The main casing 290 is deployed in the wellbore 292 prior to drilling the wellbore 292 with the system 200. In one aspect, outer structure 250 includes a sealing device 285 for providing a seal between outer structure 250 and main sleeve 290. The outer structure 250 also includes a receiver 284 at its upper end, which may include a protective sleeve 281 having internal splines 282a and collet grooves 282 b. A debris barrier 283 may also be provided to prevent cuttings formed by the pilot bit 202, under reamer 212, and/or reamer 251 from entering the space or annulus between the inner structure 210 and the outer structure 250.

To drill the wellbore 292, the inner structure 210 is placed inside the outer structure 250 and attached to the outer structure 250 at the lower landing 252 by activating the attachment devices 236a,236b of the tailpipe drive subs 236 as shown. When activated, the tailpipe drive sub 236 connects the attachment device 236a to the internal spline 252a and the attachment device 236b to the collet groove 252b in the lower landing 252. In this configuration, pilot bit 202 and underreamer 212 extend beyond reamer 251. In operation, the drilling fluid 207 powers the drilling motor 208, which rotates the pilot bit 202 to drill the pilot bore 292a, while the underreamer 212 enlarges the pilot bore 292a to the diameter of the wellbore 292. In addition to rotating the pilot bit 202 and under reamer 212 via motor 208, the pilot bit and under reamer may also be rotated by rotating the bit system 200.

Generally, three different configurations and/or operations are performed with the system 200: drilling, reaming and cementing. In the drilling position, the Bottom Hole Assembly (BHA) is fully extended out of the liner to achieve full measurement and steering capabilities (e.g., as shown in fig. 2). In the reamed position, only the first fracturing apparatus (e.g., pilot bit 202) is outside the liner to reduce the risk of pipe or drill string seizure in the event of a well collapse, and the remainder of the BHA is contained within the outer structure 250. In the cementing position, the BHA is deployed inside the outer structure 250, at a distance from the second fracturing equipment (e.g., reamer bit 251) to ensure a proper streamer casing string.

When performing downhole operations, it is advantageous to monitor what is happening downhole, using a system such as that shown and described above in fig. 1-2. Some such solutions include Wired Pipe (WP), where monitoring is performed using one or more sensors and/or devices, and the collected data is transmitted via special drill pipe (e.g., "long cables"). Another solution has been to communicate via Mud Pulse Telemetry (MPT), using the drilling fluid as the communication channel. In such embodiments, pressure pulses (codes) are generated downhole and pressure transducers convert the pressure pulses into electrical signals (codes). Mud pulse telemetry is very slow (e.g., one thousand times slower) compared to wired pipe. A particular piece of information is a location. This is particularly true when it is desired to perform downhole operations at very specific points along the wellbore, such as, but not limited to, packer deployment, reaming, under-reaming, attaching or connecting an inner string to an outer string, and/or extending stabilizers, anchors, blades, slips or hangers, and the like.

Embodiments of the present disclosure relate to downlink activated setting tools for liner drilling applications or other applications of one structure within another (e.g., wireline applications), where the one and the other structure may be moved together (e.g., moved together as a single motion) or independently of each other (e.g., one moved while the other is stationary) by surface equipment. In the case of liner drilling applications, the liner and associated completion equipment are brought downhole during drilling operations (e.g., as shown in the arrangement of fig. 2). In the case of wireline applications or other similar applications, a wireline tool or other internal structure may be inserted into and transported through the external structure to a location where a downhole operation is to be performed.

In one non-limiting example, the internal structure has a hanger activation sub that is a drill string component and is connected to the bottom hole assembly bus system for power and communication. In this example, once the liner drilling system reaches a target depth within the borehole, the hanger activation sub is positioned proximate to and/or at the liner hanger. The hanger activation sub (which includes an activation tool, which may be part of the inner structure) contains at least one packing element (also referred to herein as an "inner engagement element") that creates a cavity inside the annulus formed between the inner and outer structures and at the sensing element through at least one activation port in an interaction device in the liner hanger. To operate, mud circulation is performed and the valve is opened to transfer the differential pressure from the central flow path (also referred to as the "bore") of the hanger activation sub to the annulus and thus to a sensing element, such as a pressure sensing element (e.g., a pressure sensor or activation piston), of the interaction device in the liner hanger. Once the hanger is set, at least one packing element (in some embodiments, two packing elements) may be depressurized and the drill string (inner structure) released from the liner (outer structure). As a non-limiting example, operation of the valve may be performed by alternative pressure transmitting devices, such as a piston or spindle valve that is mechanically, hydraulically, and/or electrically driven. In the absence of mud flow within the borehole, a pumping device inside the internal structure may provide a pressure differential to activate the interaction device.

Turning now to fig. 3, a schematic diagram of a system 300 is shown, according to an embodiment of the present disclosure. In this embodiment, similar to the embodiments described above, the inner structure 310 is adapted to pass through an outer structure 350 driven by ground equipment and connect to the interior 350a of the outer structure 350 at a plurality of spaced apart locations (also referred to herein as "landings" or "landing locations"). The illustrated embodiment of the outer structure 350 includes three land portions, a lower land portion 352, a middle land portion 354, and an upper land portion 356. In yet another embodiment, there may be one, two, three, or more land portions. The inner structure 310 includes a drilling assembly 320 on a lower end thereof, similar to that shown and described above.

As noted above, the inner structure 310 may interact with the outer structure 350, such as by engagement between an inner downhole tool 358 (such as a hanger activation sub, which is part of the inner structure 310) and a portion of the outer structure 350 (such as the hanger 370). In some embodiments, as indicated, the internal downhole tool 358 is a hanger activation sub capable of extending downhole that can extend and/or interact with a portion of the outer structure 350. Although shown and described herein with respect to engagement between a hanger activation sub (of an inner structure) and a hanger (of an outer structure), those skilled in the art will appreciate that any type of downhole operation and/or tool arrangement may employ embodiments of the present disclosure.

Turning now to fig. 4A-4D, schematic diagrams of operations according to non-limiting embodiments of the present disclosure are shown. Fig. 4A-4D show the operational sequence of the hanger activation sub, which includes an activation tool 402 operating on an interactive device 404. The activation tool 402 is part of an internal structure 406 that is movable within and through an external structure 408 that includes the interaction device 404. One or more portions of the internal structure 406, including the activation tool 402, may be manipulated to act upon, engage with, or otherwise interact with a portion of the external structure 408, such as the inner surface 408a of the external structure 408 and/or the interaction device 404.

Interaction of the activation tool 402 with the interaction device 404 in the external structure 408 may be facilitated by mechanical, electrical, acoustic, and/or optical interaction. The activation tool 402 includes an internal engagement element. The interior engagement element includes at least one of a malleable element, an electrical element, an acoustic element, and/or an optical element. The one or more extendable elements may be packers, snorkels, pistons, grippers, blades, rods and/or ribs. The electrical, acoustic and/or optical elements may be electrical, acoustic and/or optical signal emitters, respectively. In case of mechanical activation of the interaction device 404, a sensor capable of detecting mechanical movements may be arranged within the interaction device 404. Mechanical activation may be detected by a button-type sensor or other type of sensor of varying complexity, such as a load sensor (e.g., pressure sensor, torque sensor, bending load sensor, etc.). In the case of electrical, acoustic, and/or optical activation of the interaction device 404, an electrical sensor (e.g., a capacitive sensor, an inductive sensor, a galvanic sensor, etc.), an acoustic sensor (e.g., a piezoelectric sensor, a tuning fork, etc.), and/or an optical sensor (e.g., a diode, etc.) may be incorporated into the interaction device 404.

As shown, the inner structure 406 and the outer structure 408 are conveyed through a main casing 410 disposed within a borehole 412 formed in a formation 414. In some embodiments, one or both of the inner structure 406 and the outer structure 408 may include a drill bit or other tool, such as shown in fig. 2-3. A tool annulus 416 is formed between the exterior of the inner structure 406 and the inner surface 408a of the outer structure 408. It may be advantageous to have the outer structure 408 fixed relative to the main sleeve 410. However, at other times, the outer structure 408 needs to be movable relative to the main sleeve 410. In this way, the engagement or securing mechanism must be able to be actuated only when needed, for example at a particular location. Thus, the system 400 includes an activation tool 402 as part of an internal structure 406 that is operable on an interactive device 404 of an external structure 408.

In this embodiment, the activation tool 402 includes a first internal engagement element 418 and a second internal engagement element 420. The interaction device 404 includes one or more external engagement elements 422. As shown in fig. 4A, the activation tool 402 is positioned at the interaction device 404 with the internal engagement elements 418,420 positioned above and below the activation ports of the sensing elements of the interaction device 404 to achieve isolation of a portion of the tool belt 416. Generally, the one or more internal engagement elements 418,420 are configured to isolate a portion of the tool annulus around the activation port of the sensing element of the interaction device 202. The activation tool 402 may include electronics and/or be operatively connected to an electronics module that may send/receive communications along a communication line and, thus, may communicate with surface equipment (e.g., the control unit 40 in fig. 1).

While the embodiment of fig. 4A shows (and describes) a dual packer arrangement to isolate an annular portion formed between an inner structure and an outer structure, various other shaped portions and/or flow barriers may be employed without departing from the scope of the present disclosure. For example, in a non-limiting embodiment, it is sufficient to establish a partial flow barrier between a valve in the activation tool of the inner structure and a flow port of the interaction device in the outer structure. This flow barrier may not span the entire annulus, but may be implemented to employ only a portion of the annulus between the inner structure and the outer structure, such as a channel-shaped connection (e.g., a cylinder) between the position of the valve in the activation tool of the inner structure and the portion of the activation tool of the interaction device of the outer structure. The channel-shaped connector may extend through the circumferential band.

In operation, the activation tool 402 may receive instructions over the downlink. These instructions may be used to perform an interactive operation, such as extending the outer engagement element 422 to operatively connect the outer structure 408 to the main sleeve 410. Upon receiving the instructions, the interior engagement elements 418,420 may be operated to isolate a portion of the tool annulus to form an isolated annulus or cavity 416a. The inner engagement members 418,420 may be packer-type members that are telescoping such that a portion of the inner engagement members 418,420 may engage the inner surface 408a of the outer structure 408 and form an isolated annulus or cavity 416a. In one non-limiting example, the inner engagement members 418,420 are compressed or squeezed to expand outwardly into engagement with the inner surface 408 a. Such engagement between the internal engagement elements 418,420 and the inner surface 408a at the interaction device 404 is illustratively shown in FIG. 4B, where an isolated annulus or cavity 416a is defined between the activation tool 402 and the inner surface 408a at the interaction device 404.

As shown in fig. 4C, the isolated annulus or cavity 416a is filled with drilling fluid. In this embodiment, by passing fluid (such as, but not limited to, mud, water, formation or production fluid, etc.) supplied through the valves of the activation tool 402, the isolated annulus or cavity 416a is pressurized by using the higher pressure inside the internal bore of the internal structure. Mud within the pressurized annulus or cavity 416b generates a pressure differential at the interaction device 404 and the one or more external engagement elements 422 will actuate. A pressure differential occurs at the interaction device 404. For example, activating a valve in the tool 402 allows fluid to flow from the internal bore into an isolated annulus or cavity. A pressure differential then exists at the interaction device 404. The side of the interactive device 404 facing the inner annulus is subjected to a different pressure than the side of the interactive device 404 facing the outer annulus. In this case, one or more malleable members (also referred to as external engagement members 422) would extend outward from the interactive device 404 of the external structure 408 and engage the main sleeve 410, as shown in fig. 4C. By way of non-limiting example, the external engagement element may be at least one of a slip, an anchor, a piston, a blade, a rib, a pincer, and/or a retainer. In some embodiments, the external structure may comprise a power source such as a battery or an alternative battery storage device, wherein this power source is arranged to provide energy to the external engagement element, if required.

In some embodiments of the present disclosure, one or more of the external engagement elements may be arranged to interact with an external structure (such as a borehole formation, a cement volume, etc.). In such embodiments, the interaction may be at least one of Formation Evaluation (FE) measurements and/or cement bond measurements. One or more external engagement elements of such embodiments may include measurement sensors including, for example, at least one of a temperature sensor, a pressure sensor, a resistivity sensor, a gamma radiation sensor, a nuclear magnetic resonance sensor, and/or a formation sampling sensor. The acquired data may be stored in non-volatile memory in an external structure for later retrieval and/or processing.

Once the one or more outer engagement elements 422 are activated or actuated, the activation tool 402 may be operated to close the valve and/or may be operated to disengage the inner engagement elements 418,420 from the inner surface 408a, thereby allowing mud to be dispersed within the tool annulus 416. As shown in fig. 4D, the tool annulus 416 is again formed without any breaks or isolated segments and is continuous along the length of the inner and outer structures 406, 408. After this operation, the inner structure 406 may be moved relative to the outer structure 408. Further, the above operations may be performed again at a second location, where the activation tool 402 interacts with a second interaction device similar to the interaction device 404 at a different location along the length of the external structure 408.

In accordance with embodiments of the present disclosure, downlink electronic activation of an activation tool is provided to enable and perform downhole operations, wherein the activation tool interacts with and/or operates on an interactive device. For example, a liner setting operation may be initiated downlink using electronic activation, and an activation tool (e.g., an inner drill string, a portion of a wireline tool) located within an outer structure (e.g., an outer drill string, a liner, etc.) may be actuated or operated to cause the outer structure to operate or act to engage and set the liner. The activation tool performs downhole operations in response to electronic commands sent over the downlink from the surface controller. Advantageously, embodiments of the present disclosure replace traditional ball drop operations with faster downlink communications, thus allowing improved operation time downhole and/or performing repeatable operations.

Downhole operations initiated electronically over the downlink are accomplished using an activation tool (e.g., an internal drill string, wireline tool, etc.) to act on an interactive device (e.g., a portion of an external drill string, liner, casing, etc.). According to a non-limiting embodiment, an activation tool of an internal structure, or a portion thereof, is downlink activated to operate and perform a first action that causes a second action to be performed by an interactive device in an external structure in which the internal structure is located.

In one non-limiting example, the transmitter may transmit downlink instructions from the surface to perform a tailpipe setting operation. In this case, the downlink is received by an internal structure having a valve section including a valve positioned between or adjacent to one or more optional internal engagement elements. The valve section may be arranged to be controllable in response to the downlink. The interior engagement element can seal a volume (e.g., an annulus between the interior structure and the exterior structure). The valve is operated (in response to a downlink command) to perform a downhole operation by delivering fluid to increase pressure in the vicinity of the inner engagement element. In various embodiments, the valve may control, for example, hydraulic fluid or drilling mud. The altered pressure (such as increased or decreased pressure) between the activation tool and the interactive device is used to operate one or more features (e.g., a liner hanger element, an attachment device, slips, etc.) on/of the interactive device.

As will be understood by those skilled in the art, embodiments of the present disclosure may be used to perform any downhole tool activation operation, and the present disclosure is not limited to packer/hanger arrangements. Embodiments of the present disclosure relate to operations that occur outside or external to an external structure or interaction device, such as operations performed by a liner hanger sub as described herein. Further, embodiments may be used to perform one or more activation operations in multiple locations along an external structure using a single activation tool of the internal structure.

As described herein and with respect to one non-limiting embodiment below, an apparatus and method for downlink activation of downhole equipment to perform downhole operations is provided. In general, embodiments relate to positioning an activation tool of an internal structure inside or near an activation port of an interaction device of an external structure, which activation device is to be activated by operation of the activation tool. In one example, compressing two internal engagement elements (e.g., packing elements) creates an isolated annulus or cavity between the internal structure and the external structure (such as between the activation tool and the interaction device). The valve of the inner structure is operated to achieve a connection (e.g., a hydraulic connection) between the inner diameter of the interaction device and the outer component of the interaction device. The hydraulic connection enables operation of the external components. For example, by allowing fluid to flow through the valve, a pressure differential is created within the annulus or cavity. The pressure difference will then hydraulically activate the components or elements of the interaction device, so that operations can be performed outside the interaction device.

In various embodiments, as described herein, during downhole operations prior to activation and/or interaction with the interaction device, the valves of the activation tool may be protected from debris and other contamination by filling the annulus around the internal structure or any other geometric type of cavity associated with the internal structure with oil and sealing it with a rubber membrane, piston, bellows, or any other type of flexible barrier seal towards the annulus or cavity between the internal and external structures. Further, in some embodiments, the pressure differential generated within the annulus or cavity between the inner structure and the outer structure for operating the interaction device may be supplemented by operation of a pulse valve, which may be used as an adjustable choke to adjust the pressure differential within the annulus or cavity. In addition, the optional packing element may be used as a pressure seal for the annulus or cavity during the cementing operation. Further, deactivation of the arrangement of the present disclosure, such as deactivation of the flow barrier, may be achieved by moving the inner structure relative to the outer structure, and thus easy disengagement or deactivation may be achieved. Alternatively, deactivation may be achieved by again using the pressure differential change.

Turning now to fig. 5A-5B, exemplary illustrations of an internal structure 502 and an external structure 504 of a system 500 according to embodiments of the present disclosure are shown. Fig. 5A illustrates various features and components of an inner structure 502 and fig. 5B illustrates a portion of the inner structure 502 within an outer structure 504 that extends entirely within the outer feature or structure 505 (e.g., formation, borehole, main casing, another liner, etc.). As shown in fig. 5B, the inner structure 502 can extend within the outer structure 504, and in various arrangements, the inner structure 502 can move within and relative to the outer structure 504.

The internal structure 502 has a control section 506, a valve section 508, and an activation section 510. One or more components of the bottom hole assembly 512 or other one or more downhole components may be below the segments 506,508, 510. Although shown as three separate segments, those skilled in the art will appreciate that various alternative arrangements are possible without departing from the scope of the present disclosure. For example, one or more of the control section 506, the valve section 508, and/or the activation section 510 may be integrally formed as a single structure, or various functions may be incorporated into other portions of the internal structure 502 at different locations. As shown, the activation segment 510 includes an activation tool 514 positioned between a first inner engagement element 516 and a second inner engagement element 518.

As shown in fig. 5B, the inner structure 502 is positioned within the outer structure 504. Further, the outer structure 504 is disposed within an outer feature 505, which is shown as a primary sleeve. Although shown and described as a casing, those skilled in the art will appreciate that the outer structure 504 may enter and pass through various other structures/features, such as a borehole or wellbore, a tubular, another liner, etc. The external structure 504 includes an interactive device 520 that is part of the external structure 504 and/or is positioned outside or external to the external structure. When arranged as shown in fig. 5B, an inner annulus 522 is formed between the inner structure 502 and the outer structure 504. The inner annulus 522 is similar to the tool annulus 416 of figures 4A-4D. An outer annulus 524 is formed between the outer structure 504 and the outer feature 505.

In operation, downlink commands may be transmitted or communicated to the control section 506 of the internal structure 502. The transmission of downlink commands/commands may be via mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, wired pipe communication, or other downlink/downhole transmission techniques known in the art. The control section 506 will then control the valve section 508 and/or the activation section 510 to perform a particular operation. In some embodiments, control of the control section 506 may include controlling the valve section 508 to act on the activation section 510. In one non-limiting example, the control section 506 controls the activation section 510 such that the inner engagement elements 516,518 extend from the inner structure 502 into engagement with the inner surface of the outer structure 504, thereby isolating the activation tool 514. The activation tool 514 may include one or more ports and may be in fluid communication with the valve section 508. When the portion of the inner annulus 522 surrounding the activation tool 514 is isolated by the inner engagement elements 516,518, the valve section 508 may control the flow of fluid (e.g., hydraulic fluid, mud, etc.) into the inner annulus 522. As fluid enters or exits inner annulus 522, the fluid pressure and/or pressure differential within inner annulus 522 changes, e.g., the pressure increases or decreases.

As the pressure differential within inner annulus 522 increases, a hydraulic force may be applied to outer structure 504, and in particular to interaction device 520 (or a portion of an interaction device). That is, by operating the activation tool 514, the interaction device 520 may be activated or operated to perform a downhole operation. In one non-limiting example, the interaction device 520 may include slips or other types of extension members that may extend due to the pressure differential and thus extend from the outer structure 504 (and in particular the interaction device 520) into engagement with the outer feature 505.

According to one non-limiting embodiment, one function of activation segment 510 is to separate or block the hydraulic path between the upper region (above activation segment 510) and the lower region (below activation segment 510) of inner annulus 522. Because of the presence of the two internal engagement elements 516,518, it is possible to isolate a certain segment of the inner annulus 522 and enable the activation segment 510 (or activation tool 514) to directly connect the central bore pressure or fluid to the inner annulus 522 and/or outer annulus 524 pressure levels or fluid by disconnecting the short circuit at a predefined location through the activation tool 514 and/or interaction device 520. This functionality may also be employed in areas where the inner structure 502 protrudes from the outer structure 504 (e.g., as shown in fig. 2-3), and may seal or isolate the area relative to the borehole wall.

As noted above, the internal structure may be divided into three main sections. A control section 506, a valve section 508, and an activation section 510. The control section 506 houses electronics and optionally hydraulic fluid including a hydraulic fluid compensation reservoir. The valve section 508 is comprised of several pockets and/or elements, including a mud valve in some configurations. At the lower end of the valve section 508, the activation section 510 is shown with two internal engagement elements (e.g., rubber packing elements) responsible for sealing the internal annulus 522 between the inner structure 502 and the outer structure 504, as described herein.

The control segment 506 controls the activation and deactivation of the valve segment 508 and the activation segment 510 and/or subcomponents thereof. Control section 506 is a power section of internal structure 502 and may be powered by one or more power mechanisms. For example, in some configurations, the control section 506 is driven by electrical power from a battery or an alternator driven by a turbine-powered mud flow, as will be understood by those skilled in the art. The electrical power may be converted to hydraulic power by an electric motor that drives a pump within the control section 506 (or positioned within another section of the internal structure 502). Further, power may be employed to power electronics, measurement equipment, and/or control valves of one or more segments of the internal structure 502.

The activation segments 510, and in particular the inner engagement elements 516,518, are configured to seal an inner annulus 522 between the inner structure 502 and the outer structure 504. The internal engagement elements 516,518 of the activation segment 510 may be activated and deactivated separately or simultaneously. In some configurations of the present disclosure, the inner engagement elements 516,518 may be operated by respective pistons. These pistons can be controlled individually by means of associated activation lines, as described below. Thus, a simple barrier may be formed against mud flow if only one of the engagement elements 516,518 is activated (e.g., compressed), or an isolation zone may be formed between the inner structure 502 and the outer structure 504 if both inner engagement elements 516,518 are activated (e.g., compressed) at the same time. In some non-limiting embodiments, the internal engagement element may be a hydraulically or pneumatically inflatable packer (inflatable packer) or a mechanically activated packer (mechanical packer).

Fig. 6A-6C are schematic diagrams of an activation segment 610 according to the present disclosure. More specifically, fig. 6A-6C illustrate the operation and/or activation of the internal engagement elements 616,618 of the activation tool 614 of the activation segment 610, which is part of the internal structure 602, according to an embodiment of the present disclosure. In this embodiment, two internal engagement elements 616,618 are activated, with the activation sequence shown in fig. 6A-6C. Fig. 6A shows the inner engagement elements 616,618 in a deactivated position and fig. 6B-6C show the inner engagement elements 616,618 in an activated position. The inner structure 602 and its activation tool 614 may be disposed and movable within the outer structure, such as shown and described above. As described above, the activation tool 614 may engage with an external structure to form an isolated annulus or cavity. To accomplish this, the activation tool 614 of fig. 6A-6C includes internal engagement elements 616,618. In this embodiment, the extension and thus engagement of the inner engagement elements 616,618 is performed by operation of a piston assembly 624 having a first piston 626 and a second piston 628.

The pistons 626,628 are actuated by fluid pressure supplied through respective first and second fluid lines 630, 632. Fluid lines 630,632 fluidly connect a fluid source (not shown), such as a hydraulic fluid source, with the cavities formed between the respective pistons 626,628 and intermediate stop element 634. As shown, the intermediate stop element 634 is a ring that is fixed to the inner structure 602, and the piston 626,628 is movable relative to the inner structure 602. The first fluid line 630 provides fluid into a first activation chamber 636 that receives fluid to hydraulically actuate the first piston 626 away from the intermediate stop element 634 and toward the first internal engagement element 616. Similarly, the second fluid line 632 provides fluid into a second activation chamber 638, which receives fluid to hydraulically actuate the second piston 628 away from the backstop member 634 and toward the second inner engagement member 618. The first internal engagement element 616 may be compressed between the first piston 626 and the upper stop element 640. Similarly, the second internal engagement element 618 may be compressed between the second piston 628 and the lower stop element 642. As fluid enters the first activation chamber 636, the fluid acts on the first piston 626 and pushes the first piston 626 to the left in fig. 6A. As fluid enters the second activation chamber 638, the fluid acts on the second piston 628 and pushes the second piston 628 to the right in fig. 6A.

Thus, in some embodiments, during an activation operation, the first piston 626 moves to the left (e.g., uphole) and the second piston 628 moves to the right (e.g., downhole). In the present arrangement, self-reinforcement is achieved when external pressure is applied between the two inner engagement elements 616,618. However, in some embodiments, this may vary if the pressure conditions are different in any other application where the pressure from the outside is higher than the pressure between the inner engagement elements 616,618.

As noted, intermediate stop element 634, which is fixed to inner structure 602, is positioned between pistons 626,628. The intermediate stop element 634 serves as a seal retainer to separate the two activation chambers 636,638 and to ensure a defined end position of the piston 626,628. Intermediate stop element 634 prevents imbalance of piston 626,628 during a deactivation operation of inner engagement elements 616,618. This is because one piston 626,628 may remain at least partially activated while the corresponding other piston 626,628 moves back to the deactivated position. Furthermore, the end position of the activated piston 626,628 is defined by the respective upper and lower stop elements 640, 642, which can be adjusted if desired. Upper stop element 640 and lower stop element 642 may prevent overstraining of inner engagement elements 616,618 when inner engagement elements 616,618 are compressed, as shown in fig. 6B-6C.

As exemplarily shown in fig. 6B, the activation operation is schematically illustrated. Fluid is transported along the first activation fluid line 630 into the first activation chamber 636. Similarly, fluid is delivered along second activation fluid line 632 into second activation chamber 638. Fluid may be supplied from the control section of the inner structure 602 as described above. The fluid may be supplied in response to downlink instructions received by the control segment from a surface controller or control unit.

As the fluid pressure and/or volume increases in the first activation chamber 636 and the second activation chamber 638, the first piston 626 and the second piston 628 are urged away from the intermediate stop member 634. The first piston 626 is pushed to the left and exerts a pressure on the first inner engagement element 616, which is delimited by the upper stop element 640. Thus, the first internal engagement element 616 is compressed and deployed outwardly from the activation tool 614, and is thus engageable with a surface of an external structure (e.g., the external structure described above). The second piston 628 is pushed to the right and exerts a pressure on the second inner engagement element 618, which is delimited by the lower stop element 642. Thus, the second inner engagement element 618 is compressed and deployed outwardly from the activation tool 614, and is thus engageable with a surface of an external structure (e.g., the external structure described above).

To deactivate the inner engagement elements 616,618, the reverse operation may be performed, as shown in FIG. 6C. As schematically shown, an optional deactivation fluid line 644 may be fluidly connected to the provided first and second deactivation chambers 646,648, and may be supplied with a fluid similar to that described above. In some embodiments, the inner engagement elements 616,618 may be formed of rubber or other spring-like material (or include mechanical biasing elements) and may be naturally deactivated or retracted due to the mechanical action of the engagement elements. Thus, once pressure from the activated fluid lines 630,632 is released, the piston 626,628 is pushed back to the deactivated (e.g., neutral) position. However, as noted, the optional deactivation chambers 646,648 may provide additional force to deactivate the inner engagement members 616,618 and/or to prevent a malfunction within the activation tool 614, such as a piston being stuck. As schematically shown, a single deactivation fluid line 644 is fluidly connected to both the first deactivation chamber 646 and the second deactivation chamber 648. However, those skilled in the art will appreciate that multiple fluid lines (similar to the first activation fluid line 630 and the second activation fluid line 632) may be employed. In this way, hydraulic deactivation may optionally be performed on one or both of the internal engagement elements 616,618.

As noted, the inner engagement members 616,618 may provide a sealing function. For example, the pressure sealing function provided by the first inner engagement element 616 (e.g., an upper or uphole engagement element) may be used during a cementing operation. When a single engagement element is activated, deactivation may be achieved by relative movement between the inner structure 602 and an outer structure to which the engagement element may be engaged. This is advantageous because communication with the activation tool 614 may not be possible at the completion of the cementing operation. In this deactivation operation, when the first internal engagement element 616 is activated and the inner structure 602 is pulled upward relative to the outer structure, the first internal engagement element 616 element compresses any fluid in the corresponding first activation chamber 636, resulting in a pressure spike. A pressure spike may be detected by activating a pressure transducer in the tool 614 (e.g., a hydraulic unit) and a deactivation routine may be executed.

Turning now to fig. 7A-7B, schematic diagrams of a valve segment 708 are shown, according to embodiments of the present disclosure. Fig. 7A shows a first view of valve section 708, which shows the inlet arrangement of valve section 708. Fig. 7B illustrates a second view of the valve section 708, which shows the outlet arrangement of the valve section 708.

For example, as shown and described above, the valve section 708 is part of the internal structure 702. The inner structure 702 is disposed within and movable along the outer structure 704, and a tool annulus 716 is formed between the inner structure 702 and the outer structure 704. The inner structure 702 includes a central flow path 750. The central flow path 750 may be used to transport drilling fluid, mud, hydraulic fluid, etc. from one location to another through the inner structure 702. As shown, the valve section 708 is positioned adjacent to the activation section 710, similar to that shown and described above. The valve section 708 includes a valve 752 fluidly connected to the central flow path 750.

The valve 752 is responsible for connecting the central flow path 750 of the inner structure 702 with the tool annulus 716 that exists between the inner structure 702 and the outer structure 704. The valve 752 is configured to allow the transmission of fluid and/or pressure if one region has a higher pressure level than another region.

For example, the pressure within the central flow path 750 may be higher than the pressure within the tool annulus 716. This may be normal when the mud flow continues and mud circulates through the central flow path 750 of the internally activated tool and then uphole through the tool annulus 716 and/or an annulus formed between the exterior of the outer structure 704 and the borehole wall 701 (i.e., the outer annulus 724). However, due to pressure losses under one or more restrictions and/or pressure losses due to friction, pressure differentials may exist between the central flow path 750 and the tool annulus 716 and/or between the central flow path 750 and the outer annulus 724.

In another example, the pressure within the central flow path 750 may be equal to the pressure within the tool annulus 716. This condition occurs when the circulation stops and the inner structure 702 is not moving, considering a homogeneous fluid along the entire fluid column.

In another example, the pressure within the central flow path 750 may be lower than the pressure within the tool annulus 716. This may be rare, but may occur where the fluid is heterogeneous, or may occur due to displacement forces if the inner structure 702 and/or outer structure 704 are lowered into the wellbore very quickly during tripping operations.

To activate the interaction device of the outer structure 704 (e.g., the interaction device 404 of FIG. 4), the first scenario described above is employed, and pressure is transmitted from the central flow path 750 to the tool annulus 716 (when isolated as described above) at the predefined location of the interaction device of the outer structure 704. As shown, the valve inlet port 754a fluidly connects the central flow path 750 of the inner structure 702 to the valve 752 along an input line 754 b. The valve outlet port 756a is on the outside of the inner structure (fig. 7B), with the valve outlet port 756a fluidly connecting the valve 752 and the central flow path 750 to the tool annulus 716 along an outlet line 756B. The two ports 754a,756a are prevented from settling via a pre-filled oil, grease, or fluid reservoir 758. Further, the valve inlet port 754a is equipped with a rubber bellows 760 that separates mud from oil. In the event of a packing element leak, the bellows 760 may be punctured to provide an unlimited supply of fluid (e.g., mud) through the valve 752.

As shown in fig. 7B, the valve outlet port 756a is positioned at the outer diameter of the inner structure 702 (and in particular the outer diameter of the valve section 708). The outlet port 756a and outlet line 756b are protected by oil to prevent settling. In one non-limiting configuration, the outlet port 756a has an insert that is equipped with a perforated membrane 774. The diaphragm 774 opens upon application of a differential pressure to the diaphragm 774, and automatically closes upon release of the differential pressure.

In some non-limiting embodiments, the pressure differential for interacting with the interaction device may be generated by a mud pump and/or a piston inside the internal structure. Furthermore, in some embodiments, the rubber bellows may be replaced by a valve or a piston. This arrangement may enable fluid to move directly from the central flow path to the tool annulus in order to change the pressure inside the annulus between the inner and outer structures.

Turning now to FIG. 8, a flow chart 800 for performing a downhole operation in accordance with the present disclosure is shown. The flow chart 800 may be performed by a downhole system as shown and described herein. Specifically, flowchart 800 is performed downhole using an outer structure having at least one interaction device and an inner structure movable within and relative to the outer structure, the inner structure having an activation tool. For example, in some embodiments, the outer structure may be an outer tubing string and the inner structure may be an inner tubing string, wherein the inner tubing string is extendable downward and indexable to perform an action with an activation tool to cause an action of the interaction device. In other embodiments, the internal structure may be a wireline tool conveyed in a liner or other casing. Various other configurations are possible without departing from the scope of the present disclosure.

At block 802, the inner structure is moved downhole along with or relative to the outer structure. The internal structure is moved such that the activation tool is aligned with the interactive device in a manner that enables operation as described herein. In some embodiments, the internal structure comprises a control section, a valve section, and an activation section, wherein the activation tool is part of the activation section.

At block 804, a downlink instruction is sent to the internal structure. This downlink may be formed by any known communication means. The internal structure may include electronics to receive downlink instructions.

At block 806, the internal structure executes an activation routine. The activation routine may be operation of a valve, piston, and/or motor to create a pressure differential inside the inner structure and/or between the central flow path and a tool annulus formed between the inner and outer structures. Alternatively, the pressure differential may be generated by an electro-hydraulic system inside the internal structure, regardless of the pressure in the central flow path. Other activation routines may be electronic, mechanical, hydraulic, and/or combinations thereof.

At block 808, the activation routine causes the external structure to execute the interaction routine. The interaction routine may be initiated by a pressure differential caused by the activation routine.

The isolation routine may be performed using the flow diagram 800, with the internal structure acting as an activation routine with respect to the external structure (as described above). Further, the interaction routine may be caused by a pressure differential within a tool annulus formed within the isolation zone between the inner structure and the outer structure. The interaction routine may be an extension of a component or some other action outside or "outside" the external structure (e.g., within the borehole and interacting with the main casing, another liner, and/or the formation wall).

One skilled in the art will appreciate that embodiments of the present disclosure may be used to perform hanger activation operations. In this embodiment, the external structure is or includes a liner hanger. In some non-limiting embodiments, the liner hanger may have any liner size, including but not limited to 7"/32# or 7"/26#.

In some embodiments, the activation segment (e.g., activation segment 610 of fig. 6A-6C) can include a stabilizer for stabilization relative to an external structure. For example, referring to fig. 6A to 6C, the upper and lower stop elements may be equipped with stabilizer pads. The stabilizer pad may be fixed to the activation section (and in particular the stop element) by screws or other fasteners and may be replaced without disassembling the entire internal structure and/or the complete section. In an alternative embodiment, the inner structure may be configured with a screw-in stabilizer, which is a simple sleeve threaded, rather than the stabilizer pad just discussed, as will be understood by those skilled in the art. Further, one skilled in the art will appreciate that any number of internal engagement elements and/or internal structural tools may be configured along the length of the internal structure.

As a non-limiting example, the interior engagement elements may be modular and/or interchangeable without requiring disassembly of the interior structure. Interchangeable internal engagement elements may allow deployment of different sized packers to service different inner diameter external structures. The packer may be made of a variety of materials including, but not limited to, natural rubber, different fluorinated elastomers (e.g., FKM, FFKM), nitrile rubbers (e.g., NBR, HNBR), etc., that can handle different drilling fluids, varying harsh drilling conditions, and/or varying temperature and/or pressure ranges. Using different end stop positions may allow for different inflatable packer diameters to be adjusted.

In some non-limiting alternative embodiments, the internal engagement element of the inner structure may be used to directly activate or deactivate a portion of the outer structure as compared to being used to generate the pressure differential. For example, the inner engagement element can be deployed to engage and/or grip the sleeve (i.e., the outer structure) and push or pull the sleeve to another location. In some embodiments, the internal engagement element may be mechanically extended (e.g., a mechanical packer), rather than relying on a hydraulically operated piston configuration as described above. Further, in some embodiments, the radial force generated by the internal engagement element (e.g., a blade or spear) may be used to directly push a portion of the external structure, e.g., a switch or release mechanism.

In some embodiments, the ability to isolate a certain segment of the tool annulus (or annulus external to the internal structure) may enable fluid sampling. For example, the internal engagement element may isolate an open hole segment or even an annulus in a perforated main casing to enable fluid sampling. In this embodiment, the fluid sampling tool and components would be part of the activation tool described herein. Furthermore, such isolation may be used to isolate perforated areas or simple holes, cracks, etc. Another application of the tool and arrangement according to the present disclosure may be to clean an outer structure by wiping the inner diameter of the outer structure with an inner engagement element of the inner structure.

Embodiment 1: a method for performing a downhole operation in a borehole, the method comprising: moving an inner structure and an outer structure within the borehole using surface equipment, the outer structure being equipped with an interaction device and the inner structure being configured to be moved relative to the outer structure by the surface equipment in a direction parallel to the borehole; transmitting, by a transmitter, a downlink instruction to an internal structure; and executing an interaction routine with the interaction device in response to the downlink instructions, wherein the interaction routine comprises an interaction located at least partially outside of the external structure to perform the downhole operation.

Embodiment 2: a method according to any of the embodiments described herein, wherein the internal structure comprises an activation tool, the method comprising executing an activation routine that initiates an interaction routine in response to the downlink instruction.

Embodiment 3: the method according to any of the embodiments described herein, wherein activating the routine comprises forming a flow barrier in a portion formed between the inner structure and the outer structure.

Embodiment 4: the method according to any one of the embodiments described herein, wherein activating the routine comprises altering a pressure formed within a portion between the inner structure and the outer structure.

Embodiment 5: the method according to any one of the embodiments described herein, wherein activating a routine comprises activating at least one internal engagement element.

Embodiment 6: the method according to any of the embodiments described herein, wherein activating at least one internal engagement element comprises deploying a packer element.

Embodiment 7: the method according to any of the embodiments described herein, wherein the at least one internal engagement element is at least one of a malleable element, an electrical element, an optical element, and an acoustic element.

Embodiment 8: the method according to any one of the embodiments described herein, wherein the interaction routine comprises activating at least one external engagement element.

Embodiment 9: the method according to any of the embodiments described herein, wherein the external structure is a first liner and the at least one external coupling element mechanically connects the first liner to at least one of the borehole, the second liner, and the casing.

Embodiment 10: the method according to any one of the embodiments described herein, wherein the downlink instructions are transmitted by at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, and wired pipe telemetry.

Embodiment 11: the method according to any of the embodiments described herein, wherein the internal structure is operated at least one of: (i) removed from the external structure after the interaction routine is executed; and (ii) move within the external structure prior to execution of the interaction routine.

Embodiment 12: a downlink activation system for performing a downhole operation, the system comprising: surface equipment for performing downhole operations; an outer structure operatively connected to surface equipment; an inner structure operatively connected to the surface equipment and disposed within the outer structure, wherein the inner structure and the outer structure are movable within the borehole by operation of the surface equipment, the outer structure includes an interaction device and the inner structure is configured to be moved by the surface equipment relative to the outer structure in a direction parallel to the borehole; wherein the internal structure is configured to receive downlink instructions; and the interaction device is configured to execute an interaction routine in response to the downlink instructions, wherein the interaction routine comprises an interaction located at least partially outside the external structure to perform the downhole operation.

Embodiment 13: the system according to any one of the embodiments described herein, wherein the internal structure comprises an activation tool configured to execute an activation routine that initiates the interaction routine in response to the transmitted downlink instruction.

Embodiment 14: the system according to any of the embodiments described herein, wherein the activation routine comprises at least one of: forming a flow barrier in a portion formed between the inner structure and the outer structure; and modifying a pressure within a portion formed between the inner structure and the outer structure.

Embodiment 15: the system according to any of the embodiments described herein, wherein the external structure is a first tailpipe and the at least one external coupling element mechanically connects the first tailpipe to at least one of the borehole, the second tailpipe, and the casing.

Embodiment 16: the system according to any of the embodiments described herein, wherein the internal structure comprises a control section, a valve section, and an activation section.

Embodiment 17: the system according to any of the embodiments described herein, wherein the valve section comprises a valve positioned between a central flow path within the inner structure and a portion formed between the inner structure and the outer structure.

Embodiment 18: the system according to any of the embodiments described herein, wherein the valve section is controllable to control at least one of a fluid pressure and a fluid flow rate of the fluid from the central flow path and the portion formed between the inner structure and the outer structure.

Embodiment 19: the system according to any of the embodiments described herein, wherein the activation segment comprises at least one internal engagement element.

Embodiment 20: the system according to any of the embodiments described herein, wherein at least one internal engagement element is a packer or a malleable element.

In support of the teachings herein, various analysis components may be used, including digital systems and/or analog systems. For example, a controller, computer processing system, and/or geographic steering system as provided herein and/or used with embodiments described herein may include a digital system and/or an analog system. These systems may have components such as processors, storage media, memories, inputs, outputs, communication links (e.g., wired, wireless, optical, or otherwise), user interfaces, software programs, signal processors (e.g., digital or analog), and other such components (such as resistors, capacitors, inductors, and the like) for providing the operation and analysis of the apparatus and methods disclosed herein in any of several ways that are well known in the art. It is contemplated that these teachings may be implemented, but are not required to be, in connection with a set of computer-executable instructions stored on a non-transitory computer-readable medium, including a memory (e.g., ROM, RAM), an optical medium (e.g., CD-ROM) or magnetic medium (e.g., diskette, hard drive), or any other type of medium, that when executed, cause a computer to implement the methods and/or processes described herein. In addition to the functions described in this disclosure, these instructions may provide equipment operation, control, data collection, analysis, and other functions that a system designer, owner, user, or other such person deems relevant. The processed data (such as the results of the implemented method) may be transmitted as a signal via the processor output interface to the signal receiving device. The signal receiving device may be a display monitor or a printer for presenting the results to the user. Alternatively or in addition, the signal receiving device may be a memory or a storage medium. It should be understood that storing the results in a memory or storage medium may transition the memory or storage medium from a previous state (i.e., containing no results) to a new state (i.e., containing results). Further, in some embodiments, an alert signal may be transmitted from the processor to the user interface if the result exceeds a threshold.

In addition, various other components may be included and required to provide aspects of the teachings herein. For example, sensors, transmitters, receivers, transceivers, antennas, controllers, optical units, electrical units, and/or electromechanical units may be included to support the various aspects discussed herein or to support other functionality beyond the present disclosure.

The use of the terms "a" and "an" and "the" and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should also be noted that the terms "first," "second," and the like, herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier "about" used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).

The one or more flow diagrams depicted herein are just examples. Many changes may be made to the diagram or to the steps (or operations) described therein without departing from the scope of the present disclosure. For instance, the steps may be performed in a differing order, or steps may be added, deleted or modified. All of these variations are considered a part of this disclosure.

It should be recognized that various components or techniques may provide certain necessary or beneficial functions or features. Accordingly, such functions and features as may be needed in support of the appended claims and variations thereof are considered to be inherently included as part of the teachings herein and as part of the present disclosure.

The teachings of the present disclosure may be used in a variety of well operations. These operations may involve treating the formation, fluids residing in the formation, the wellbore, and/or equipment in the wellbore, such as production tubing, with one or more treatment agents. The treatment agent may be in the form of a liquid, a gas, a solid, a semi-solid, and mixtures thereof. Exemplary treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brines, corrosion inhibitors, cements, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, mobility improvers, and the like. Exemplary well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water injection, cementing, and the like.

While the embodiments described herein have been described with reference to various embodiments, it will be understood that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the disclosure. In addition, many modifications may be made to adapt a particular instrument, situation or material to the teachings of the disclosure without departing from the scope thereof. Therefore, it is intended that the disclosure not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out the described features, but that the disclosure will include all embodiments falling within the scope of the appended claims.

Accordingly, the embodiments of the present disclosure should not be viewed as limited by the foregoing description, but rather should be limited only by the scope of the appended claims.

Claims (16)

1. A method of performing a downhole operation in a borehole (26,412), the method comprising:

moving an inner structure and an outer structure within the borehole (26,412) using surface equipment, the outer structure equipped with an interaction device (202,404,520) and the inner structure configured to move relative to the outer structure in a direction parallel to the borehole (26,412) by the surface equipment, wherein a tool annulus (716) is formed between the inner structure and the outer structure, the inner structure comprising a central flow path (750), a control section (506), a valve section (508,708), and an activation section (510,610,710);

controlling operation of the valve section (508,708) and activation section (510,610,710) by the control section;

changing pressure in the tool annulus (716) with the valve segment (508, 708) by means of pressure transmission from the central flow path (750) to the tool annulus (716);

transmitting, by a transmitter (66a, 66b), a downlink instruction to the control segment; and

executing an interaction routine with the interaction device (202,404,520) in response to the downlink instructions and the changed pressure in the tool annulus, wherein the interaction routine comprises an interaction located at least partially outside of the external structure to perform the downhole operation.

2. The method of claim 1, wherein the active segment comprises an activation tool (402,514,614), the method comprising executing an activation routine that initiates the interaction routine in response to the downlink instruction.

3. The method according to claim 2, wherein activating the at least one internal engagement element (418,420,516,518,616,618) when activating the at least one internal engagement element (418,420,516,518,616,618) comprises deploying a packer element and/or wherein the at least one internal engagement element (418,420,516,518,616,618) is at least one of a malleable element, an electrical element, an optical element, and an acoustic element.

4. The method of claim 1, wherein the interaction routine comprises activating at least one external engagement element (422).

5. The method of claim 1, wherein the downlink instructions are transmitted by at least one of mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, and wired pipe telemetry.

6. The method of claim 2, wherein the activation routine comprises at least one of: forming a flow barrier in a portion formed between the inner structure and the outer structure; modifying a pressure within a portion formed between the inner structure and the outer structure; and/or activating at least one internal engagement element (418,420,516,518,616,618).

7. The method of claim 4 wherein the external structure is a first tailpipe and the at least one external coupling element (422) mechanically connects the first tailpipe to at least one of the borehole (26,412), a second tailpipe, and a casing.

8. The method according to any of the preceding claims 1-7, wherein the inner structure is operated at least one of: (i) Removing from the external structure after execution of the interaction routine; and (ii) move within the external structure prior to execution of the interaction routine.

9. A downlink activation system for performing a downhole operation, the downlink activation system comprising:

surface equipment for performing downhole operations;

an outer structure operably connected to the surface equipment;

an inner structure operably connected to the surface equipment and disposed within the outer structure, wherein the inner structure and the outer structure are movable within a borehole (26,412) by operation of the surface equipment, the outer structure includes an interaction device (202,404,520) and the inner structure is configured to move relative to the outer structure by the surface equipment in a direction parallel to the borehole (26,412), wherein a tool annulus (716) is formed between the inner structure and the outer structure;

wherein the inner structure comprises a central flow path (750), a control section (506), a valve section (508,708), and an activation section (510,610,710), the control section controlling operation of the valve section (508,708) and activation section (510,610,710);

wherein the pressure in the tool annulus (716) is varied by means of pressure transmission from the central flow path (750) to the tool annulus (716) with the valve section (508, 708);

wherein the control segment is configured to receive a downlink instruction; and is

The interaction device (202,404,520) is configured to execute an interaction routine in response to the downlink instructions and the changed pressure in the tool annulus, wherein the interaction routine comprises an interaction located at least partially outside of the external structure to perform the downhole operation.

10. The downlink activation system of claim 9, wherein the activation segment comprises an activation tool (402,514,614) configured to execute an activation routine that initiates the interaction routine in response to the transmitted downlink instruction.

11. The downlink activation system of claim 10, wherein the activation routine comprises at least one of: forming a flow barrier in a portion formed between the inner structure and the outer structure; and modifying a pressure within a portion formed between the inner structure and the outer structure.

12. The downlink activation system of claim 11, wherein the external structure is a first tailpipe and at least one external coupling element (422) mechanically couples the first tailpipe to at least one of the borehole (26,412), a second tailpipe, and a casing.

13. The downlink activation system according to claim 9, wherein the valve section (508,708) comprises a valve located between a central flow path (750) within the inner structure and a portion formed between the inner structure and the outer structure.

14. The downlink activation system of claim 13, wherein the valve section (508,708) is controllable to control at least one of a fluid pressure and a fluid flow rate of fluid from the central flow path (750) and the portion formed between the inner structure and the outer structure.

15. The downlink activation system according to claim 13 or 14, wherein the activation section (510,610,710) comprises at least one internal engagement element (418,420,516,518,616,618).

16. The downlink activation system according to claim 15, wherein said at least one internal engagement element (418,420,516,518,616,618) is a packer element or an extendable element.

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